The present invention relates to methods and apparatus for separating a feed gas, comprising carbon dioxide (CO2), hydrogen sulfide (H2S) and hydrogen (H2), to form an H2-enriched product gas and a sour gas depleted in H2 and enriched in CO2 and H2S relative to the feed gas, and for adjustably treating said sour gas to produce an H2S-lean, CO2 product gas. The invention has particular application to the separation and treatment of sour syngas mixtures obtained from the gasification or reformation of carbonaceous feedstock.
The production of syngas via reforming or gasifying carbonaceous feedstock is well known. Where the feedstock contains sulfur, such as is often the case for solid (e.g. coal, petcoke) or heavy liquid (e.g. asphaltene) feedstocks for gasification, such processes result in an initial syngas stream containing hydrogen (H2), carbon monoxide (CO), carbon dioxide (CO2), hydrogen sulfide (H2S) and, usually, other species such as methane (CH4), carbonyl sulfide (COS) and carbon disulfide (CS2). Commonly, the initial syngas mixture (crude syngas) is then subjected to further treatments. In particular, the initial syngas mixture may be subjected to a water-gas shift reaction, in which at least some of the CO present in the initial syngas mixture is converted to further CO2 and H2 by reaction with H2O in the presence of a suitable shift catalyst. This process can also result in further H2S being produced, via incidental conversion of other sulfur species (such as COS and CS2) in the syngas during the water-gas shift reaction.
Due to concerns over greenhouse gas emissions, there is a growing desire to remove CO2 from syngas prior to use of the remaining, H2-enriched, product (comprising predominantly either H2 or a mixture of H2 and CO) as a combustion fuel or for chemicals production or refining applications. The CO2 may be compressed, so as to be stored underground or used for enhanced oil recovery (EOR). H2S may also have to be removed from the syngas. If the H2-enriched product is to be used for chemicals production or refining then H2S, if present, could be a poison for these downstream processes. Equally, if the H2-enriched product is to be combusted in a gas turbine to production or refining then H2S, if present, could be a poison for these downstream processes. Equally, if the H2-enriched product is to be combusted in a gas turbine to generate power then H2S, if present, will be converted into SOx (SO2 and SO3), on which there are emission limits and which may, therefore, require removal from the combustion exhaust using expensive desulfurization technology. Equally, it may not be practical or permissible to store the H2S with the CO2. Therefore a solution must likewise be found for cost effective removal of H2S from the CO2 before pipeline transportation or geological storage.
The most commonly used commercial solution, currently, for capturing CO2 and H2S from sour syngas mixture uses a physical solvent (i.e. liquid solvent) absorption process, also referred to as an acid gas removal (AGR) process, such as Selexol™ or Rectisol®, to selectively separate H2S, CO2 and product H2 into different streams. The H2S-rich stream, typically containing about 20-80 mole % H2S, is further treated to produce sulfur, usually by a Claus process coupled with a tail gas treating unit (TGTU). The CO2 stream is typically compressed to meet pipeline or storage specifications, and the product H2 is either sent as fuel to a gas turbine for power generation, or can be further processed via pressure swing adsorption (PSA) to achieve a ‘spec’ purity (typically 99.99 mole % or higher) for refining applications. However, a disadvantage of such AGR processes is that they are both costly and have significant power consumption.
As mentioned above, the typical method of removing the H2S contained in the H2S-rich stream obtained from the AGR process is via conversion to elemental sulfur using the Claus process. This process, as is well known, typically involves an initial thermal step followed by one or more catalytic steps. In the thermal step the H2S-rich stream is reacted in a substoichiometric combustion at high temperatures to convert part of the H2S to SO2. The oxidant (i.e. O2) to H2S ratio during combustion is controlled so that in total one third of all H2S is converted to SO2. This provides the correct 2:1 molar ratio of H2S to SO2 for the subsequent catalytic steps. More specifically, in said subsequent catalytic steps, the 2:1 mixture of H2S to SO2 obtained from the thermal step is reacted over a suitable catalyst (e.g. activated aluminium(III) or titanium(IV) oxide) to convert the H2S and SO2 to elemental sulfur via the reaction 2H2S+SO2→⅜S8+2H2O. The Claus process ordinarily achieves high (e.g. 94 to 97%) but not complete levels of sulfur recovery and thus, as noted above, a TGTU is often also employed to recover and/or remove the remaining H2S from the Claus process tailgas.
The Claus process is at its most economical when greater than 20 short tons per day (tpd) sulfur (about 18000 kg/day sulfur) is to be produced, and when the H2S concentration in the feed to the process is greater than 10 mole %, and more preferably greater than 20 mole %. For production rates of less than 20 tpd (18000 kg/day) sulfur and/or for feed streams that are more dilute in H2S concentration other, more economical, means of removing sulfur are generally preferred. Typically, these are catalyst-based processes that can be of the regenerable type or the ‘once-and-done’ scavenging type and require a varying degree of process complexity and operational cost depending on the processing conditions of the gas being treated. Typically, these processes are most suited for treating feeds with H2S concentrations of less than 5%, and for processes where less than 20 tpd (18000 kg/day) is to be produced (although larger units have been designed and built). These processes are typically capable of removing 99% or more of the H2S from the feed. Industry accepted examples of such H2S disposition technologies include the LO-CAT and Stretford processes.
Specific examples of known prior art processes for separating H2S, and/or other sulfur containing compounds, from a mixture include the following.
US-A1-2007/0178035, the disclosure of which is incorporated herein by reference, describes a method of treating a gaseous mixture comprising H2, CO2 and at least one combustible gas selected from the group consisting of H2S, CO and CH4. The gaseous mixture, which may be obtained from the partial oxidation or reforming of a carbonaceous feedstock, is separated, preferably by pressure swing adsorption (PSA), to produce a separated H2 gas and a crude CO2 gas comprising the combustible gas(es). The crude CO2 gas is then combusted in the presence of O2 to produce heat and a CO2 product gas comprising the combustion product(s) of the combustible gas(es). The heat from at least a portion of the CO2 product gas is recovered by indirect heat exchange with the separated H2 gas or a gas derived therefrom. Where the combustible gas is, or includes, H2S, the combustion products will include SO2 and SO3 (SOx). In one embodiment, the SOx is then removed by washing the CO2 product gas with water to cool the gas and remove SO3, and maintaining the cooled SO3-free gas at elevated pressure in the presence of O2, water and NO to convert SO2 and NO to sulfuric acid and nitric acid, thereby obtaining an SOx-free, NOx-lean CO2 gas.
The process described in this document therefore presents a sulfur disposition pathway in which the H2S in the sour tailgas stream leaving the PSA is ultimately converted to sulfuric acid after being combusted to form SOx. This process presents a alternative to the conventional elemental sulfur disposition pathway and can, additionally, handle dilute H2S concentrations as well as varying total amounts of sulfur. However, market conditions could limit the economic viability of such a sulfur disposition pathway, as the acid produced from such a process may be unsalable or of sufficiently poor quality that costly neutralization and disposal may be required.
U.S. Pat. No. 6,818,194 describes a process for removing H2S from a sour gas, wherein the sour gas is fed to an absorber where the H2S is removed from the gas by a nonaqueous sorbing liquor comprising an organic solvent for elemental sulfur, dissolved elemental sulfur, an organic base which drives the reaction between H2S sorbed by the liquor and the dissolved sulfur to form a nonvolatile polysulfide which is soluble in the sorbing liquor, and a solubilizing agent which prevents the formation of polysulfide oil. The process further comprises adding SO2 to the absorber to oxidize the polysulphide to elemental sulfur, thereby producing a more complete chemical conversion of H2S by reducing the equilibrium back-pressure of H2S. The sweet gas from the absorber exits the process, and the sorbent stream is then cooled and fed to a crystallizer to crystallize enough of the sulfur to balance the amount of H2S previously absorbed.
In this process, the optimum molar ratio of H2S to SO2 in the feed stream to the absorber is the same as that for the catalytic stage of the Claus process, i.e. 2:1. In one embodiment, the process is applied to a feed stream which already contains a 2:1 mole ratio of H2S to SO2, such as where the feed stream is the tail gas of a Claus process which is operated so as to produce a tail gas with this composition. In another embodiment, the process may be applied to an H2S containing feed stream to which SO2 is first added, so as to obtain the desired 2:1 ratio prior to the stream being flowed through the absorber vessel. One exemplified way in which this may be achieved is to split the feed stream into two streams, pass one of said streams through a catalytic oxidation reactor to convert at least some of the H2S contained therein to SO2, and then recombine the streams.
U.S. Pat. No. 4,356,161 describes a process for reducing the total sulfur content of a high CO2-content feed gas stream, comprising CO2, H2S and COS. The feed gas is first passed to an absorption column where it is contacted with an a regenerable, liquid polyalkanolamine absorbent selective for H2S. The unabsorbed gas stream, comprising CO2 and COS and substantially free of H2S is then routed to a reduction step where it is combined with Claus off-gases and the COS reduced to H2S. The treated gas is then passed to a second absorption column and the unabsorbed gas is vented to the atmosphere. The H2S-rich solvent from both absorption columns is stripped in a common stripper and the H2S-rich gas is passed to a Claus unit for conversion to elemental sulfur. The absorption process described in this document is commonly referred to in the industry as an ‘acid gas enrichment’ process.
U.S. Pat. No. 5,122,351 describes a refinement to the known LO-CAT and Stretford processes of removing H2S by conversion to elemental sulfur, whereby the catalytic polyvalent metal redox solution used in said processes is recovered and re-used. This is achieved by interposing a closed loop evaporator/condenser process in the sulfur washing/filtering/recovery process so that wash water used to purify the sulfur and any polyvalent metal redox solution recovered from the sulfur melter are fed to an evaporator to concentrate the redox solution to a concentration capable of effective absorption of H2S, and the water evaporated in the evaporator is condensed as pure water for use in washing and/or filtering the recovered sulfur.
US-A1-2010/0111824 describes a process for producing H2 from a hydrocarbonaceous feed such as refinery residues, petroleum, natural gas, petroleum gas, petcoke or coal. In the exemplified embodiment, a crude syngas comprising H2, CO, CO2 and H2S, is formed by gasifying residue oils, quenching the raw syngas, and subjecting the quenched syngas to a water-gas shift reaction. The syngas is separated via PSA into an H2 product and a tail gas enriched in CO2 and containing also H2S, H2 and CO. The PSA tail gas is mixed with a Claus process tail gas and the mixture supplied to a tail gas cleaning stage that uses a liquid solvent such as MDEA or Flexsorb SE® to selectively wash out H2S from the gas mixture. H2S is then liberated from the solvent and added to the feed stream to the Claus process.
U.S. Pat. No. 5,248,321 describes a process for removing sulfur oxides from gaseous mixtures such as flue gases from power plants, smelter gases, and other gases emitted from various industrial operations. The process involves contacting the gaseous mixture with a non-functionalized polymeric sorbent which is essentially hydrophobic, such as styrenic polymers, which sorbent may be employed in a PSA system to selectively adsorb SO2. The SO2 rich desorption stream may be fed to a Claus reactor along with a suitable amount of H2S to produce elemental sulfur and water.
U.S. Pat. No. 7,306,651 describes the separation of a gas mixture comprising H2S and H2 using the combination of a PSA unit with a membrane. The PSA separates the feed stream into an H2 stream and two H2S-rich streams. One H2S-rich stream is recovered as a waste stream and the second is compressed and put through a membrane to remove the H2. The H2S is then supplied to the PSA unit at pressure for rinsing and the H2 returned to the PSA unit for purging. The gas mixture may, for example, be a stream obtained from a hydrodesulfurization process in a refinery. The H2S-rich waste stream may be fed into one of the fuel/sour gas lines of the refinery.
EP-B1-0444987 describes the separation of CO2 and H2S from a syngas stream produced by gasification of coal. The syngas stream, containing H2S, is reacted with steam in a catalytic CO-shift reactor to convert essentially all the CO in the stream to CO2. The shifted stream is sent to a PSA unit that adsorbs CO2 and H2S in preference to H2, to separate said stream into an H2 product gas and a stream containing CO2 and H2S. The stream containing CO2 and H2S is sent to a second PSA unit that adsorbs H2S in preference to CO2, to provide a CO2 product, stated to be of high purity, and a H2S containing stream, the latter being sent to a Claus unit for conversion of the H2S into elemental sulfur.
EP-A1-0633219 describes a process for removing sulfur compounds from a gas stream containing sulfur compounds, such as the off-gas from a Claus process. The process comprises the steps of: (a) converting the sulfur compounds to sulfuric acid, by combusting sulfur compounds other than SO2 to form SO2, and catalytically oxidizing SO2 to SO3, which then forms sulfuric acid in water; (b) separating the sulfuric acid from the gas stream; and (c) supplying the sulfuric acid into the thermal stage of a Claus process to allow the sulfuric acid to react with hydrogen sulfide to form elemental sulfur.
Similarly, U.S. Pat. No. 4,826,670 describes a process for improving an oxygen-enriched Claus process by introducing a sulfuric acid stream into the reaction furnace (thermal stage of the Claus process) to moderate oxygen-induced high temperatures which allow oxygen-enrichment and attendant throughput in the Claus process to higher levels.
Industries must strike a delicate balance when selecting technologies for processing sour feeds. A successful project must minimize capital and operating cost while ensuring the chosen technologies can appropriately and robustly meet ever tightening emissions standards. The final selection of H2S disposition technology can, as discussed above, depend on the concentration at which the H2S is present in the sour gas stream that is being treated. Where CO2 is to be captured (either for underground storage or enhanced oil recovery), the presence of H2S in the CO2 product presents regulatory concerns and careful design measures must be in place to ensure product purity is upheld. This becomes an even more complex problem when one considers that the amount of H2S in the sour gas stream can vary depending on feedstock variations, and variations in the process used to produce and/or separate out the sour gas. Significant variation in the amount of H2S may, in turn, lead to the H2S removal process becoming economically disadvantageous and/or to product purity and/or emission standards being compromised.
It is an object of embodiments of the present invention to provide methods and apparatus that allow for variations in the H2S content of the sour gas while meeting air emissions standards and/or CO2 purity specifications and achieving cost advantages over conventional technologies for sour gas processing.
It is an object of embodiments of the present invention to provide methods and apparatus that are capable of processing sour gas streams from varying feedstocks with varying compositions.